A variety of industrial as well as non-industrial applications use fuel burning boilers which typically operate to convert chemical energy into thermal energy by burning one of various types of fuels, such as coal, gas, oil, waste material, etc. An exemplary use of fuel burning boilers is in thermal power generators, wherein fuel burning boilers generate steam from water traveling through a number of pipes and tubes within the boiler, and the generated steam is then used to operate one or more steam turbines to generate electricity. The output of a thermal power generator is a function of the amount of heat generated in a boiler, wherein the amount of heat is directly determined by the amount of fuel consumed (e.g., burned) per hour, for example.
In many cases, power generating systems include a boiler which has a furnace that burns or otherwise uses fuel to generate heat which, in turn, is transferred to water flowing through pipes or tubes within various sections of the boiler. A typical steam generating system includes a boiler having a superheater section (having one or more sub-sections) in which steam is produced and is then provided to and used within a first, typically high pressure, steam turbine. To increase the efficiency of the system, the steam exiting this first steam turbine may then be reheated in a reheater section of the boiler, which may include one or more subsections, and the reheated steam is then provided to a second, typically lower pressure steam turbine. While the efficiency of a thermal-based power generator is heavily dependent upon the heat transfer efficiency of the particular furnace/boiler combination used to burn the fuel and transfer the heat to the water flowing within the various sections of the boiler, this efficiency is also dependent on the control technique used to control the temperature of the steam in the various sections of the boiler, such as in the superheater section of the boiler and in the reheater section of the boiler.
However, as will be understood, the steam turbines of a power plant are typically run at different operating levels at different times to produce different amounts of electricity based on energy or load demands. For most power plants using steam boilers, the desired steam temperature setpoints at final superheater and reheater outlets of the boilers are kept constant, and it is necessary to maintain steam temperature close to the setpoints (e.g., within a narrow range) at all load levels. In particular, in the operation of utility (e.g., power generation) boilers, control of steam temperature is critical as it is important that the temperature of steam exiting from a boiler and entering a steam turbine is at an optimally desired temperature. If the steam temperature is too high, the steam may cause damage to the blades of the steam turbine for various metallurgical reasons. On the other hand, if the steam temperature is too low, the steam may contain water particles, which in turn may cause damage to components of the steam turbine over prolonged operation of the steam turbine as well as decrease efficiency of the operation of the turbine. Moreover, variations in steam temperature also cause metal material fatigue, which is a leading cause of tube leaks.
Typically, each section (i.e., the superheater section and the reheater section) of the boiler contains cascaded heat exchanger sections wherein the steam exiting from one heat exchanger section enters the following heat exchanger section with the temperature of the steam increasing at each heat exchanger section until, ideally, the steam is output to the turbine at the desired steam temperature. In such an arrangement, steam temperature is controlled primarily by controlling the temperature of the water at the output of the first stage of the boiler which is primarily achieved by changing the fuel air mixture provided to the furnace or by changing the ratio of firing rate to input feedwater provided to the furnace/boiler combination. In once-through boiler systems, in which no drum is used, the firing rate to feedwater ratio input to the system may be used primarily to regulate the steam temperature at the input of the turbines.
While changing the fuel/air ratio and the firing rate to feedwater ratio provided to the furnace/boiler combination operates well to achieve desired control of the steam temperature over time, it is difficult to control short term fluctuations in steam temperature at the various sections of the boiler using only fuel/air mixture control and firing rate to feedwater ratio control. Instead, to perform short term (and secondary) control of steam temperature, saturated water is sprayed into the steam at a point before the final heat exchanger section located immediately upstream of the turbine. This secondary steam temperature control operation typically occurs before the final superheater section of the boiler and/or before the final reheater section of the boiler. To effect this operation, temperature sensors are provided along the steam flow path and between the heat exchanger sections to measure the steam temperature at critical points along the flow path, and the measured temperatures are used to regulate the amount of saturated water sprayed into the steam for steam temperature control purposes.
In many circumstances, it is necessary to rely heavily on the spray technique to control the steam temperature as precisely as needed to satisfy the turbine temperature constraints described above. In one example, once-through boiler systems, which provide a continuous flow of water (steam) through a set of pipes within the boiler and do not use a drum to, in effect, average out the temperature of the steam or water exiting the first boiler section, may experience greater fluctuations in steam temperature and thus typically require heavier use of the spray sections to control the steam temperature at the inputs to the turbines. In these systems, the firing rate to feedwater ratio control is typically used, along with superheater spray flow, to regulate the furnace/boiler system. In these and other boiler systems, a distributed control system (DCS) uses cascaded PID (Proportional Integral Derivative) controllers to control both the fuel/air mixture provided to the furnace as well as the amount of spraying performed upstream of the turbines.
However, cascaded PID controllers typically respond in a reactionary manner to a difference or error between a setpoint and an actual value or level of a dependent process variable to be controlled, such as a temperature of steam to be delivered to the turbine. That is, the control response occurs after the dependent process variable has already drifted from its set point. For example, spray valves that are upstream of a turbine are controlled to readjust their spray flow only after the temperature of the steam delivered to the turbine has drifted from its desired target. Needless to say, this reactionary control response coupled with changing boiler operating conditions can result in large temperature swings that cause stress on the boiler system and shorten the lives of tubes, spray control valves, and other components of the system.